Well control is of the utmost importance during drilling operations. Numerous well control incidents occur on land and offshore rigs. The consequences of a loss in well control can be devastating. Hydrocarbon reservoirs and facilities may be damaged, costing millions of dollars. Substantial damage to the environment may also result. The greatest risk, however, is the threat to human life. As technology advances, wells are drilled to greater distances with more complex geometries. This includes multilateral and extended-reach horizontal wells. In wells with inclinations greater than horizontal or horizontal wells with washouts, buoyancy forces may trap kick gas in the wellbore. The trapped gas creates a greater degree of uncertainty regarding well control procedures, which if not handled correctly can result in a greater kick influx or loss of well control. For this study, a three-phase multiphase flow simulator was used to evaluate the interaction between a gas kick and circulating fluid. An extensive simulation study covering a wide range of variables led to the development of a best-practice kick circulation procedure for multilateral and extended-reach horizontal wells. The simulation runs showed that for inclinations greater than horizontal, removing the gas influx from the wellbore became increasingly difficult and impractical for some geometries. The higher the inclination, the more pronounced this effect. The study also showed the effect of annular area on influx removal. As annular area increased, higher circulation rates are needed to obtain the needed annular velocity for efficient kick removal. For water as a circulating fluid, an annular velocity of 3.4 ft/sec is recommended. Fluids with higher effective viscosities provided more efficient kick displacement. For a given geometry, a viscous fluid could remove a gas influx at a lower rate than water. Increased fluid density slightly increases kick removal, but higher effective viscosity was the overriding parameter. Bubble, slug, and stratified flow are all present in the kick-removal process. Bubble and slug flow proved to be the most efficient at displacing the kick.

Managed Pressure Drilling now at the pinnacle of the 'Oil Well Drilling' evolution tree, has itself been coined in 2003. It is an umbrella term for a few new drilling techniques and some preexisting drilling techniques, all of them aiming to solve several drilling problems, including non-productive time and/or drilling flat time issues. These techniques, now sub-classifications of Managed Pressure Drilling, are referred to as 'Variations' and 'Methods' of Managed Pressure Drilling. Although using Managed Pressure Drilling for drilling wells has several benefits, not all wells that seem a potential candidate for Managed Pressure Drilling, need Managed Pressure Drilling. The drilling industry has numerous simulators and software models to perform drilling hydraulics calculations and simulations. Most of them are designed for conventional well hydraulics, while some can perform Underbalanced Drilling calculations, and a select few can perform Managed Pressure Drilling calculations. Most of the few available Managed Pressure Drilling models are modified Underbalanced Drilling versions that fit Managed Pressure Drilling needs. However, none of them focus on Managed Pressure Drilling and its candidate selection alone. An 'Managed Pressure Drilling Candidate Selection Model and software' that can act as a preliminary screen to determine the utility of Managed Pressure Drilling for potential candidate wells are developed as a part of this research dissertation. The model and a flow diagram identify the key steps in candidate selection. The software performs the basic hydraulic calculations and provides useful results in the form of tables, plots and graphs that would help in making better engineering decisions. An additional Managed Pressure Drilling worldwide wells database with basic information on a few Managed Pressure Drilling projects has also been compiled that can act as a basic guide on the Managed Pressure Drilling variation and project frequencies and aid in Managed Pressure Drilling candidate selection.

ABSTRACT HYDRAULICS OPTIMIZATION OF FOAM DRILLING IN DRILLING OPERATIONS &Ouml / zer, Ceren M. Sc., Department of Petroleum and Natural Gas Engineering Supervisor: Assoc. Prof. Dr. Evren &Ouml / zbayoglu September 2009, 72 pages In drilling, drilling fluid affects every single step of operation. If rig system is thought as the human body, drilling mud can be defined as the blood system of it. Drilling fluid carries the cuttings, cools the bit, it conditions the hole and so on. Some special kinds of drilling fluids are used for special purposes such as underbalanced drilling. Underbalanced drilling is generally used to prevent formation damage, lost circulation and to increase the penetration rate.Since 1980&rsquo / s foam is used as drilling fluid for underbalanced drilling purposes and there are some models for bit hydraulic optimizations. In this study, mathematical model has been derived considering not the volumetric flow rate but the mass flow rate of the foams. Maximum hydraulic horse power at the bit is determined as a function of mass flow rate. Using this concept, optimum volumetric flow rates for liquid and gas phases as well as optimum nozzle size are determined.Using this mathematical model, a computer program is developed for comparing the results with the existing data available in the literature. It accounts for the compressibility of foam and pressure losses inside the drill string, bit and annulus.Hole size, drill-string properties, formation temperature and pressure, maximum inlet pressure are used as input parameters. Program calculates static back pressure,pressure losses in the whole system, bottom hole foam properties such as quality and velocity and optimum liquid and gas flow rates which are the key parameters of foamdrilling optimization. Results show that liquid and gas rates should be increased with increasing hole sizeand formation pressure. Increasing temperature gradient causes a minimal decrease on foam rate properties. In addition, pressure losses due to friction increases with increasing hole size and formation pressure. Decrease in formation temperature also decreases the foam quality. Changes in temperature gradient causes minimal changes on foam rate properties. Comparisons of the proposed model with other models from the literature also gave good match. The optimization criteria and assumptions are differing from the existing models. As a result the comparison does not have to one to one match with the others. The results from this study may be used for optimization of flow rate of foam as drilling fluid based on mass flow.

The studies conducted on hole cleaning have been started with single phase drilling fluids for vertical holes in 1930&rsquo / s, and have reached to multiphase drilling fluids for directional and horizontal wells today. The influence of flow rate and hole inclination on cuttings transport has been well understood, and many studies have been conducted on effective hole cleaning either experimentally or theoretically. However, neither the hydraulic behavior nor the hole cleaning mechanism of gasified drilling fluids has been properly understood. The aims of this study are to investigate and analyze the hole cleaning performance of gasified drilling fluids in horizontal, directional and vertical wells experimentally, to identify the drilling parameters those have the major influence on cuttings transport, to define the flow pattern types and boundaries as well as to observe the behavior of cuttings in detail by using digital image processing techniques, and to develop a mechanistic model based on the fundamental principles of physics and mathematics with the help of the experimental observations. A mechanistic model is developed with the help of the obtained experimental data. Developed model is used for estimating optimum flow rates for liquid and gas phases for effective cuttings transport as well as for determining the total pressure losses and void fraction of each phase for a given drilling conditions. The v mechanistic model obtained using the experimental data within the scope of this study will be used to develop the hydraulic program and equipment selection to be used in the field during underbalanced drilling applications.

The supply and demand situation is crucial for the oil and gas industry during the first half of the 21st century. For the future, we will see two trends going in opposite directions: a decline in discoveries of conventional oil and gas reservoirs and an increase in world energy demand. Therefore, the need to develop and produce unconventional oil and gas resources, which encompass coal-bed methane, gas-shale, tight sands and heavy oil, will be of utmost importance in the coming decades. In the past, large-scale production from tight gas reservoirs occurred only in the U.S. and was boosted by both price incentives and well stimulation technology. A conservative study from Rogner (1997) has shown that tight gas sandstone reservoirs would represent at least over 7,000 trillion cubic feet (Tcf) of natural gas in place worldwide. However, most of the studies such as the ones by the U.S. Geological Survey (U.S.G.S.) and Kuuskraa have focused on assessing the technically recoverable gas resources in the U.S. with numbers ranging between 177 Tcf and 379 Tcf. During the past few decades, gas production from tight sands field developments have taken place all around the world from South America (Argentina), Australia, Asia (China, Indonesia), the Russian Federation, Northern Europe (Germany, Norway) and the Middle East (Oman). However, the U.S. remains the region where the most extensive exploration and production for unconventional gas resources occur. In fact, unconventional gas formations accounted for 43% of natural gas production and tight gas sandstones represented 66% of the total of unconventional resources produced in the U.S. in 2006. As compared to a conventional gas well, a tight gas well will have a very low productivity index and a small drainage area. Therefore, to extract the same amount of natural gas out of the reservoir, many more wells will have to be drilled and stimulated to efficiently develop and produce these reservoirs. Thus, the risk involved is much higher than the development of conventional gas resources and the economics of developing most tight gas reservoirs borders on the margin of profitability. To develop tight gas reservoirs, engineers face complex problems because there is no typical tight gas field. In reality, a wide range of geological and reservoir differences exist for these formations. For instance, a tight gas sandstone reservoir can be shallow or deep, low or high pressure, low or high temperature, bearing continuous (blanket) or lenticular shaped bodies, being naturally fractured, single or multi-layered, and holding contaminants such as CO2 and H2S which all combined increase considerably the complexity of how to drill a well. Since the first tight gas wells were drilled in the 1940's in the U.S., a considerable amount of information has been collected and documented within the industry literature. The main objective of this research project is to develop a computer program dedicated to applying the drilling technologies and methods selection for drilling tight gas sandstone formations that have been documented as best practices in the petroleum literature.